0

AER submission

Review into the scope of

economic regulation applied to

covered pipelines

August 2017

1

Contents

Executive summary ........................................................................................ 2

1. Introduction ........................................................................................... 6

2. Efficient and effective regulatory framework ..................................... 6

2.1 There are many benefits to the negotiate-arbitrate model, but it is not

beyond questioning ....................................................................................... 6

2.2 An incentive-based regime provides many benefits ........................ 7

2.3 Multiple levels of discretion should be removed.............................. 8

3. Efficient investment in gas pipelines ............................................. 11

3.1 Assessments on conforming capex could be improved ................ 11

3.2 Expansions to a covered pipeline should be covered ................... 14

3.3 Other suggestions to improve the effectiveness of the Part 9 rules15

4. Incentives to provide access to pipeline services ........................... 16

4.1 AEMC must ensure the AER is able to define reference and

rebateable services ....................................................................... 16

4.2 Introduce a mechanism to consult prior to access arrangement

reviews.......................................................................................... 19

4.3 Information requirements for light regulation should be enhanced 20

4.4 Arbitration mechanism should be clarified and more transparent . 23

Attachment 1: Gas pipelines subject to regulation by the AER ......... 26

2

Executive summary

There has been significant change in the gas market over the past 15 years, and we

expect this to continue.

In particular, the gas transmission pipeline network has undergone a major

transformation in response to market forces, including investment in new pipelines and

a number of significant incremental investments in existing pipelines. The east coast is

now an interconnected market where shippers can move gas across states in

directions that were not envisaged 15 years ago.

Such industry transformation puts a spotlight on the cost of transportation, as one of

the components of the delivered price of gas. Despite the changes in the flow of gas,

and growth in the transmission pipeline network, the fundamental characteristics of the

gas network remain unchanged.

Gas pipelines are natural monopolies operated by private businesses engaging in

medium to long term commercial contracts with customised offerings. If there is any

doubt about this:

the ACCC, in its East Coast Gas Inquiry (Inquiry) found that a large number of

transmission pipelines are taking advantage of their market power by engaging in

monopoly pricing.1

Dr Michael Vertigan undertook his own analysis and confirmed the ACCC's findings

that pipelines are exercising market power and this is resulting in inefficient

outcomes.2

A well-designed and targeted legislative and regulatory access framework is therefore

essential. The National Gas Law (NGL) and the National Gas Rules (NGR) provide the

framework for gas regulation. Regulation is based around a negotiate-arbitrate model.

The negotiate-arbitrate framework is an appropriate model for a sector that provides

customised services, particularly when the end-customers themselves are large

commercial entities. This framework makes judgments and balances competing

interests. For example, it balances the cost of regulation (administrative costs and

potential impacts on innovation) against the benefits of regulatory outcomes.

The Terms of Reference for the AEMC Review focuses on Parts 8-12 of the National

Gas Rules (the rules), which cover the economic regulation of covered pipelines.

From our operational experience we consider that the rules are flexible and adaptable.

For example, we consider the rules provide guidance suitable to regulate both contract

carriage and market carriage models. We also consider that the foundation of the

1 ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p. 110.

2 Dr Michael Vertigan AC, Examination of the current test for the regulation of gas pipelines, 14 December 2016, p.

35.

3

regulatory regime, which is determining prices for services using the building block

approach, is well understood. In fact the importance of having regard to cost when

pricing services was affirmed most recently by Dr Michael Vertigan.3

However, given changing market dynamics due to interconnection, where gas is being

transported around the east coast in directions never envisaged, there may be issues

in transmission pipeline regulation that require reflection, both on the part we play in

applying the rules, and also in the rules themselves. In particular, we consider there

may be issues in appropriately identifying and defining services, given the different

services sought by shippers as the market evolves. The ability to effectively define

services is critical to the success of the gas regulation regime in addressing market

power.

The transformation of the gas market is leading pipeline operators to become more

innovative with their services. While we support this innovation we do not support

monopoly pricing of such services. Our submission goes into detail regarding a

pathway forward on this, but we also consider that there are a number of issues that

require further consideration.

Recommendations

The purpose of our submission is to provide suggestions on how the rules could be

improved in the short term to better respond to the transformation occurring in the gas

market. These are:

Recommendation 1: In order to be able to respond to a dynamic and evolving

market, it is recommended that rules 79(6), 89(3), 91(2), 94(6) and 95(4) be

removed as these rules limit the AER's discretion.

Recommendation 2: Expansions should automatically form part of the covered

pipeline.

Recommendation 3: To improve efficiency and consistency, pipeline operators

should be required to use the AER models (PTRM/RFM) as part of the access

arrangement review. We also recommend that the rules provide for explicit

indexation of the capital base.

Recommendation 4: The AEMC should ensure the rules place beyond doubt the

AER's ability to set multiple reference tariffs and to define and set rebateable

services.

Recommendation 5: Introducing an upfront process to identify reference services,

rebateable services, application of incentives schemes and the form of control prior

the commencement of an access arrangement review.

Recommendation 6: Enhancing the AER's information disclosure powers over

light regulation pipelines. We consider the amount of public information should be

3 Gas Market Reform Group, Gas Pipeline Information and Arbitration Framework, Initial National Gas Rules,

Explanatory Note, 2 August 2017.

4

expanded and not just made available at the request of the access seeker via the

regulator.

Recommendation 7: Subject to acceptance of Recommendation 6, the AER can

improve the arbitration process through removing areas of uncertainty, introducing

clear timeframes and aiming to minimise costs for disputing parties in its arbitration

guideline. The AER would undertake a public process to revise its guidelines at the

completion of the AEMC review. We are also cognisant of picking up lessons learnt

from the non-scheme arbitration process which commenced on 1 August 2017.

These recommendations are commensurate with improving the operation of the

existing regime. They will also improve the certainty of regulation for pipelines under

Parts 8-12 and can be implemented now.

In the submission we also highlight that it would be worth further considering whether

the negotiate-arbitrate model is the best fit for distribution pipelines,4 and whether a

contingent project mechanism could be an addition to rule 79.5 However, we make no

specific recommendations on these matters at this point as they deserve broader

consultation.

The varied layers of gas regulation

The efficiency of the gas market is critically dependent on the efficiency of the

transmission and distribution sectors, the prices pipeline operators charge for

transportation services and the ability of participants to respond to change.

The ACCC Inquiry found that while the market is responding to substantial change,6

concerns have been raised about 'the market power wielded by pipeline operators, the

ways in which this market power is being exercised and the detrimental effect it is

having on economic efficiency and consumers more generally'.7 The ACCC Inquiry

found that market power is being exercised through monopoly pricing.8 Monopoly

pricing gives rise to a higher delivered gas price for consumers and products and

services produced using gas.

The AER regulates covered gas distribution and transmission pipelines in all states

and territories, except Western Australia. Currently we regulate ten pipelines under full

regulation; of those, four are transmission pipelines, which amounts to less than 20 per

cent of the transmission pipelines on the east coast (see Attachment A for the list of

the pipelines we regulate).9 We have reached this point because over time regulation

4 Please see 2.1 of this submission.

5 Please see 3.1 of this submission.

6 ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p. 95.

7 ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p. 92.

8 ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p. 102.

9 ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p. 100.

5

has been revoked on a number of key pipelines and a large number of new pipelines

have been developed not having to be subject to regulation.10

As the ACCC has noted, this relatively small number of pipelines subject to full

regulation is in direct contrast to what occurs in other comparable jurisdictions, such as

the US, European Union and New Zealand, where the vast majority of transmission

pipelines are regulated.11 We believe that the coverage test and the form of regulation

should be reviewed. A key element of such a review, will be questioning the form of

regulation, in particular the objective/purpose of light regulation, given Part 23 of the

rules.

Ensure change and reform is staged and incremental

We are proposing specific incremental recommendations to enhance the operation of

Parts 8-12 that we consider can be implemented now, and that improve transparency

and certainty.

We stress caution in considering more radical change to the gas pipeline sector at this

juncture. Part 23 - the Information Disclosure and Arbitration Framework for non-

scheme pipelines - has only just become operational. It will be a material change to the

industry. It is important to let this new part of the NGR settle and assess its

effectiveness in two years as planned. That said, there may be aspects of the non-

scheme pipeline framework that should also be considered, in one form or another, as

additions/amendments to Parts 8-12.

We are also conscious that the ACCC Inquiry into Gas Market Transparency Measures

(announced in April 2017) will be an invaluable source of information, in a sector

starved of information disclosure.12 Such information may provide evidence (following

the information gathering exercise the ACCC is undertaking) into areas where further

enhancements can be made to the gas regime, including the regulatory framework. In

this context we may make further recommendations to the AEMC during the course of

its review.

We encourage the AEMC in making recommendations for change to undertake a

staged approach, which engages with all stakeholders.

As these reforms proceed, the AER looks forward to a transparent and productive

working environment with industry and consumers.13

10

For example, coverage was removed on the Dawson Valley pipeline (2014) and the Moomba to Adelaide Pipeline

System (2005). There was also a move to light regulation for the covered part of the Moomba to Sydney Pipeline.

See, National Competition Council, Past applications < http://ncc.gov.au/applications-past/past_applications >. 11

ACCC, ACCC Inquiry into the East Coast Gas Market, April 2016, p.10. 12

ACCC, Gas Market Transparency Measures < https://www.accc.gov.au/regulated-infrastructure/energy/gas-

market-transparency-measures>. 13

AER, 2017 ENA Regulation Seminar speech: Working together to restore confidence in energy regulation, 26 July

2017 https://www.aer.gov.au/news/2017-ena-regulation-seminar-speech-working-together-to-restore-confidence-

in-energy-regulation.

6

1. Introduction

The Terms of Reference ask the AEMC to make recommendations on any

amendments it considers necessary to Parts 8-12 of the NGR to address concerns that

pipelines subject to full regulation are able to exercise market power to the detriment of

economic efficiency and the long term interests of consumers.14

Parts 8-12 of the rules set out the economic framework for the regulation of gas

transmission and distribution pipelines on the basis that these assets are monopoly

infrastructure, as assessed by the National Competition Council (NCC). The objective

of these parts of the rules is set out in the NGL.15

The purpose of this submission is to present specific suggestions on how the rules

could be enhanced to better respond to the transformation occurring in the gas market.

Our comments are structured to reflect the AEMC's assessment approach, as outlined

in the Issues Paper.16 Our comments fall under three of the five assessment topics,

specifically:

Efficient and effective regulatory framework,

Efficient investment in gas pipelines, and

Incentives to provide access to pipeline services.

2. Efficient and effective regulatory framework

2.1 There are many benefits to the negotiate-arbitrate model,

but it is not beyond questioning

We support the National Gas Objective and consider it sets the appropriate target for

regulation.17

The negotiate-arbitrate framework is an appropriate model for a sector that provides

customised services, particularly when the end-customers themselves are large

commercial entities. This form of regulation does not seek to regulate every

commercial arrangement that is entered into by end-customers, rather it fixes prices for

certain 'typical', 'benchmark' or 'reference' services.

14

COAG Energy Council, Terms of Reference, Australian Energy Market Commission, Review into the scope of

economic regulation applied to covered pipelines, p. 3. 15

National Gas Law, Part 3. 16

AEMC, Issues paper, Review into the scope of economic regulation applied to covered pipelines, 27 June 2017,

p.41. 17

NGL, s 23.

7

In order to minimise the exercise of market power, emphasis should be placed on

information disclosure, ensuring all necessary services are defined, and that the

arbitration mechanism provides appropriate dispute resolution when negotiations fail.

However, in many ways the negotiate-arbitrate framework sits more comfortably with

transmission pipelines than it does with distribution pipelines. There are fewer services

offered by distribution pipelines and they are more standardised than those offered on

transmission pipelines, meaning tariffs charged for distribution pipelines are more likely

to reflect the reference services.

Given this, when investigating the best framework for regulating distribution pipelines, it

will be important for the AEMC to decide whether tailoring terms and conditions has

value for distribution pipelines and their customers. If it does not, we question the value

of having the negotiate-arbitrate framework for distribution, and whether more specific

price determinations, such as those in electricity may be more appropriate. Pipeline

operators and gas retailers would be in a good position to provide advice and evidence

to the AEMC on this matter.

Our position is that the regulatory framework, as set out in the rules, enables flexibility

for the regulation of both transmission and distribution pipelines. This flexibility

provides the AER, the businesses and end-users the ability to create tailored access

arrangements.

2.2 An incentive-based regime provides many benefits

We use incentive-based regulation across all the energy networks we regulate.

Incentive-based regulation provides service providers with financial incentives to run

their business more efficiently. This involves financial rewards where operators

improve their efficiency and financial penalties where they become less efficient.

Consumers ultimately benefit from improved efficiency through lower regulated prices.

Most access arrangements come up for review every five years. If a service provider is

able to deliver the reference service(s) at a lower cost than the building blocks we

forecast prior to the start of the access arrangement period, both consumers and the

operator share the benefits.

More efficient expenditure will benefit consumers because:

Only actual capex is added to the capital base during the next access arrangement

review. So lower capex will, over time, put downward pressure on prices.

For opex, we use historical expenditure to inform our forecasts, so lower actual

opex will also put downward pressure on prices in the future.

Incentives to deliver an efficient service can be enhanced through the use of specific

incentive schemes. Rule 98 provides for a full access arrangement to include one or

more incentive scheme to further encourage efficiency. As the Issues Paper highlights

the incentive scheme provisions in the rules are much less prescriptive than they are in

the electricity rules. We are of the view that rule 98 allows both the AER and the

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service provider to exercise judgment, which helps to deliver fit for purpose incentive

schemes.

We have approved access arrangements which include an Efficiency Benefit Sharing

Scheme (EBSS), and more recently we approved, in our draft decision for AusNet and

AGN, a Capital Expenditure Sharing Scheme (CESS).18 Both these schemes

encourage businesses to look for efficiencies during the access arrangement period. In

regards to the CESS, AusNet and AGN undertook a thorough and responsive

stakeholder consultation process, which we participated in, prior to lodging their

proposals. This assisted the businesses to propose an incentive scheme that was

tailored and in the long term interests of consumers.

2.3 Multiple levels of discretion should be removed

The ACCC Inquiry identified and discussed the changing dynamics in the east coast

gas market.19 As the regulator we are becoming increasingly aware that in this

evolving market the number of services demanded by shippers is broadening (see Box

1).

Box 1: Services provided by transmission pipelines

Transportation services

Transmission pipelines operating on a point-to-point basis usually offer:

Forward haul services, which provide for the transportation of gas from a receipt point to a

delivery point in the direction of the predominant flow of gas; and

Backhaul services, which involve the ‘virtual transportation’ of gas in the opposite direction

to the predominant flow of gas. The term ‘virtual transportation’ is used in this context,

because a backhaul service does not involve the physical transportation of gas. It instead

involves a physical swap of gas at the point at which it is supplied into the pipeline for an

equivalent amount of gas at the backhaul delivery point. To be able to provide this service,

the volume of gas being backhauled must be less than, or equal to, the volume of gas to be

transported on a forward haul basis, which is why it is offered on an as available or

interruptible basis.

If a pipeline can physically flow in both directions across its full length (ie a bi-directional

pipeline), then it will usually offer a single transportation service, which enables gas to be

transported in either direction.

Forward haul and bi-directional services can be provided on:

a firm basis – a firm service allows shippers to transport gas up to their maximum daily and

18

See, AER, AusNet Services - Access Arrangement 2018-22, Draft Decision < https://www.aer.gov.au/networks-

pipelines/determinations-access-arrangements/ausnet-services-access-arrangement-2018-22/draft-decision>,

AER, Australian Gas Networks (Victoria and Albury) - Access Arrangement 2018-22

<https://www.aer.gov.au/networks-pipelines/determinations-access-arrangements/australian-gas-networks-victoria-

and-albury-access-arrangement-2018-22/draft-decision>. 19

ACCC, Inquiry into the East Coast Gas Market, April 2016, Box 6.1, p. 95.

9

hourly capacity reservation. The priority accorded to this service in terms of scheduling is

higher than any other services and is the last service to be curtailed.

an as available basis – an as available service allows shippers to transport gas without

reserving and having to pay for capacity on a daily basis, if there is spare capacity

available. The priority accorded to this service is lower than that accorded to a firm

transportation service in terms of scheduling and is curtailed before firm services.

an interruptible basis – an interruptible service also allows a buyer to transport gas without

reserving and paying for capacity on a daily basis. However, the priority accorded to this

service in terms of scheduling is usually lower than as available services and is usually

curtailed ahead of both as available and firm services.

Storage services

Transmission pipelines may also be used to provide the following storage related services:

Park services, which allow shippers to inject more gas into a pipeline than they take out on

a particular day, up to a specified level and to store that gas in the pipeline. The additional

gas supplied into the pipeline may be withdrawn by shippers at a later point in time, subject

to constraints in their transportation contracts.

Park and loan services, which in addition to allowing shippers to store gas on the pipeline,

also allows shippers to inject less gas than it takes on any given day (a loan), up to a

specified level.

Ancillary services

Transmission pipelines can be used to provide a range of ancillary services, including:

o Renomination services, which enable shippers to amend their nominations after the

nomination cut-off time, which is typically the afternoon before the gas day.

o In-pipe trade services, which enable gas to be traded between shippers at a notional

point on the pipeline and allow shippers to manage their imbalances.

o Capacity trading services, which enables capacity traded between shippers to be

managed by the pipeline operator rather than by the shippers (e.g. the shipper

purchasing the capacity can make nominations directly to the pipeline rather than

through the shipper selling the capacity). Note that the AEMC has recommended, as

part of its capacity trading related reforms, that any trades carried out through the

capacity trading exchange and day-ahead auction be given effect through this

service. Pipeline operators will therefore have an effective monopoly on the

provision of these services if this recommendation is implemented.

If the AER is to apply a forward looking approach and accommodate change then the

rules need to be flexible enough to account for the different ways gas will be

transported, and the changing services that shippers require.

Rule 40(2) of the NGR says:

If the Law states that the AER's discretion under a particular provision of the Law is limited, then the AER may not withhold its approval to an element of an access arrangement proposal that is governed by the relevant provision if the AER is satisfied that it:

(a) complies with applicable requirements of the Law; and

(b) is consistent with applicable criteria (if any) prescribed by the Law.

10

As set out in the Issues Paper, the AER has limited discretion in select rules in Part 9

of the NGR, specifically:

r 79 – New capital expenditure criteria

r 89 – Depreciation criteria

r 91 – Criteria governing operating expenditure

r 94 – Tariffs – distribution pipelines

r 95 – Tariffs – transmission pipelines

We consider that these limitations on the regulator's discretion under the gas rules

should be removed.

For the purpose of this submission, we will focus on rules 95 and 79 (discussed in

section 3.1) - however the points are in principle the same across the rules where the

AER's decision making is limited.

Clearly there is limited incentive for a service provider to nominate more than one

reference service and to identify any rebateable services. This is because if a service

is not identified in an access arrangement it is the subject of negotiation. Any revenue

the service provider earns from negotiable services is outside the revenue allowance

forecast in the access arrangement. If a dispute arises over the negotiated service,

then it can be the subject of arbitration.

The rules provide for the consideration and assessment of the reasonableness of

prices for firm transportation services. These rules are a critical element of the

regulatory regime because they establish the price and basis on which shippers should

expect to be able to access pipeline services. However, under rule 95 the AER’s

discretion is limited.

This provision is limiting in a dynamic market, for transmission pipelines, and works

against the objective of identifying reasonable terms. The current rules lock in the cost

recovery methodology. Once a total revenue requirement is determined using the

building block approach, the service provider determines how that revenue is to be

recovered.

The AER needs to be able to look beyond what is proposed in a service provider’s

Access Arrangement proposal and in a dynamic market, limiting the AER’s discretion

inhibits our ability to account for potential change that the service provider may be

reluctant to accept. By way of example, we understand that backhaul and derivative

services are often priced as a multiple of or discount to firm transportation services. A

service provider can propose the value of the multiple or discount to be applied to a

derivative service. The limited discretion means that the AER is constrained in

challenging proposals made by the service provider on the multiple or discount to be

applied. Unlike in other countries where broad principles have been adopted to guide

the setting of prices, no such principles exist in Australia.

The GMRG looked extensively at the issue of whether there was value in specifying

pricing principles for services that are a derivative of, or ancillary to, firm transportation

11

services and added a section to the pricing principles.20 Such a provision may warrant

further consideration as part of this review.

We are not proposing more prescription to the rules, and we believe change can be

made simply by removing the AER’s limited discretion. The AER would continue to be

bound by the requirements of the National Gas Objective and the revenue and pricing

principles in the NGL.

In summary, the original design of the rules was a propose/respond model, and layers

of discretion were built into the design. However our regulatory approach has evolved

over time, and importantly, so too has the gas transportation sector. Going forward, we

consider flexibility in the gas rules is critical, in particular for gas transmission pipelines.

Recommendation 1: In order to be able to respond to a dynamic and evolving market,

it is recommended that rules 79(6), 89(3), 91(2), 94(6) and 95(4) be removed as these

rules limit the AER's discretion.

3. Efficient investment in gas pipelines

3.1 Assessments on conforming capex could be improved

As part of our access arrangement review we assess the pipeline operator's capex

proposal and include a capex allowance in our final decision. The decision to actually

invest rests with the pipeline operator, and this is consistent with our incentive-based

regulatory approach. Actual capex is then rolled into the asset base at the next access

arrangement review (subject to our ex post assessment).

The Issues Paper notes that we assess forecast capital expenditure against rule 79 to

determine whether it is forecast conforming capital expenditure. The Issues Paper

explains that the criteria in rule 79(1) includes the overarching requirement that:

(a) the capital expenditure must be such as would be incurred by a prudent service provider acting efficiently, in accordance with accepted industry practice, to achieve the lowest sustainable cost of providing services.

In addition, under 79(2) the expenditure must meet either one or more of:

(a) positive overall economic value (having regard to the service provider, producers, users and end users)

(b) present value of expected incremental revenue must exceed the present value of the capital expenditure

(c) the expenditure is necessary to maintain the safety or integrity of services or to meet regulatory obligations or to meet the level of demand existing at the time the expenditure is incurred.

20

GMRG, Gas Pipeline Information Disclosure and Arbitration Framework - Implementation Options Paper, March

2017, p. 134.

12

Notably, the discretion of the regulator is limited for this rule.21

The Issues Paper raises the question of whether an appropriate level of regulatory

scrutiny on investment occurs when the regulator's discretion is limited.

Rules 79(2)(a) and 79(2)(b) are quite clear and may be assessed objectively in

practice.

Rule 79(2)(c) is an area where limited discretion has the potential to limit the level of

scrutiny on investments. For example, if a regulated business proposes to augment its

network to meet a safety obligation, limited discretion means we cannot change the

nature of this augmentation unless doing so would correct non-compliance with the

safety obligation. However, this does not strictly suggest that the level of approved

capex is inefficient or not appropriately scrutinised.

Rule 79(1)(a) also applies. Although this does not necessarily mean that the capex

must provide an economic benefit, it effectively says that the service provider must

propose an amount of capex necessary to undertake the proposed project in the most

prudent and efficient manner.

Rule 74 is applied where the proposed capex relies on a forecast or estimate. Our

assessment of prudent and efficient costs typically involves scrutinising volumes and

unit rates proposed by the service provider. Under rule 74:

(1) Information in the nature of a forecast or estimate must be supported by a statement of the basis of the forecast or estimate.

(2) A forecast or estimate:

(a) must be arrived at on a reasonable basis; and

(b) must represent the best forecast or estimate possible in the circumstances.

In order to assess proposed volumes (such as length of mains or number of meters)

we typically rely on engineering advice and historical data. This ensures that we accept

volumes that are in line with historical performance or industry standards. The unit

rates proposed by service providers may be previously tendered or forecast rates. We

check that existing unit rates have been subject to a competitive tender process, and

where they are forecast, we scrutinise the methodology used to derive the forecast. In

summary, rule 74 allows us to scrutinise a forecast or estimate and ensure it is

reasonable. Importantly, under rule 74 we have full discretion, which means that we

can replace a forecast or estimate if we consider that a preferable alternative exists.

In practice, rule 74 may be more effective in assessing capex that is routine in nature

(for example, new connections, mains replacement and meter replacement). In these

circumstances, forecasts or estimates can be assessed objectively against historical

performance.

21

NGR, r. 79(6).

13

Is there a better way to manage significant but uncertain capex?

We have also encountered proposals from distribution businesses where the proposed

capex volumes varied greatly from historical amounts. For example, the Victorian gas

distribution businesses proposed volumes of mains replacement for the 2013–17

access arrangement period that were significantly greater than the volumes achieved

in the preceding access arrangement period (where each business had underspent its

capex for mains replacement). We considered whether the proposed volumes of mains

replacement met the prudency and efficiency requirements of rule 79(1), and made

provision for a pass through event. This allowed the businesses, after they had

delivered the total historical volume of mains replacement, to apply for additional

expenditure. This provided us with a degree of oversight on the capex incurred during

the access arrangement period, and ensured that capex underspends of the same

magnitude would not occur again.

It is more challenging to assess estimates of volumes or unit rates for projects that are

discrete or unique in nature. This is likely to be more common for transmission

pipelines due to the characteristics of these pipelines. In these cases there may be

uncertainty around whether the project is actually required, as well as the costs

associated with the proposed project.

In response to these situations we are interested in analysing the merits of a

contingent project mechanism in the rules. This would provide a formal mechanism for

preventing large disparities in the capex we approve and the actual capex incurred by

service providers. Such a mechanism might be a more workable option to the

speculative capital account.22

Under the NER, the contingent project mechanism allows us to determine an amount

of capital expenditure for a project that is contingent on an event or condition

occurring.23 Specifically, the occurrence of the event or condition must be probable

during the regulatory control period, but the inclusion of capex is not appropriate due to

uncertainty that the event will occur, or the costs associated with the event or condition

are not sufficiently certain.24 Proposed contingent capital expenditure must also exceed

either $30 million or 5 per cent of the value of the annual revenue requirement for the

first year of the regulatory control period, whichever is the larger amount.25

In summary, we consider an appropriate level of scrutiny can be undertaken within the

current rules. However, while the rules, as a package, provide us with the necessary

tools to effectively scrutinize a proposal, the removal of limited discretion would enable

us to more actively engage with businesses in developing alternative capital

expenditure projects and proposals.

22

NGR, r. 84. 23

NER, cl. 6.6A.1. 24

NER, cl. 6.6A.1(c)(5). 25

NER, cl. 6.6A.1(b)(2)(iii).

14

3.2 Expansions to a covered pipeline should be covered

The ACCC Inquiry highlighted gaps in the regulatory regime that are enabling pipelines

subject to full regulation to exercise market power and therefore engage in monopoly

pricing.26

A pipeline may be expanded in order to provide incremental services. Under the

current regulatory regime, expansions to fully regulated pipelines are not automatically

considered part of the covered pipeline. This means that there may be capacity on a

covered pipeline, which is not subject to regulation.

Section 18 of the NGL states that an expansion forms part of a covered pipeline to

which an access arrangement applies, if it is provided for under the expansion

provisions in the access arrangement.27 Rule 104 of the NGR provides that an access

arrangement must include provisions setting out whether the access arrangement is to

apply to expansions or how this would be decided at a later time. If expansions are to

be included in a full access arrangement, the requirements must deal with the effect on

tariffs.28 This rule therefore enables the pipeline operator to determine its own

expansions policy, which is approved by the AER as part of the access arrangement

process.

We consider that pipeline operators should not have discretion to put forward an

expansion policy which enables an expansion to a covered pipeline, to be excluded

from coverage. All expansions to a pipeline subject to full regulation should be

automatically covered. The AER should not need to make a decision on whether or not

an expansion should be covered.

The ACCC Inquiry noted that if the AER allowed an expansion to a covered pipeline to

be excluded from coverage, the only available remedy to users would be to apply to

the NCC for coverage of the expansion.29 The AER agrees that this would be difficult.

The AER also recognises there are issues associated with having capacity on a

covered pipeline, which is not subject to regulation (for example, cost allocation).

Section 19 of the NGL explains that extensions and expansions to a pipeline subject to

light regulation (if there is no limited access arrangement) are automatically considered

part of the covered pipeline unless the AER determines otherwise in writing.30 We do

not consider that it is appropriate that there should be discretion for expansions to

pipelines subject to full regulation, when the default position for light is coverage.

Recommendation 2: Expansions should automatically form part of the covered

pipeline.

26

ACCC, Inquiry into the East Coast Gas Market, April 2016, p.141. 27

NGL, s.18. 28

NGR, r.104. 29

ACCC, Inquiry into the East Coast Gas Market, April 2016, p.135. 30

NGL, s.19.

15

3.3 Other suggestions to improve the effectiveness of the

Part 9 rules

Mandated use of PTRM and RFM

We believe our consultation and assessment of access arrangements will be improved

by requiring the use of the Post Tax Revenue Model (PTRM) and the Roll Forward

Model (RFM) for gas service providers. These models are required to be used under

the NER,31 and consultation with stakeholders occurs formally when required, but this

is currently not the case with gas stakeholders.

There are clear efficiencies for both the AER and pipeline operators in using consistent

models, which implement the common post-tax regulatory framework. We note that:

Reviewing different models is resource intensive.

Different models raise the prospect of errors going undetected as modellers are

required to familiarise themselves with more models.

Making changes to bespoke models adds complexity, particularly when they feed

into other business specific models - creating potential for error unless a change is

followed though.

Identifying areas of confidentially is more challenging in bespoke models, as

compared to the systematic process the AER has developed for electricity

regulation.

Comparability of the models submitted by different businesses is reduced for all

stakeholders. This reduces the ease of benchmarking businesses and other

comparative analysis.

Indexation of the capital base

The NGR requires use of a nominal weighted average cost of capital (WACC) which is

similar to the NER.32 This means there are two options for applying the nominal WACC

to the capital base in calculating the return on capital. The two options and the impact

on the revenue profile of the service provider are:

Index the capital base and make an offsetting revenue adjustment. This is the

approach the AER uses in its electricity and gas decisions. This approach

promotes a relatively flat recovery profile of revenue over the life of an asset; or

Not index the capital base, which means the assets remain at historical cost.

Relative to the approach of indexing the capital base this effectively brings forward

cash flow for the service provider, creating a steeper downward sloping revenue

recovery profile, which in turn raises issues of how to manage and smooth this

path.

31

NER, cl 6.4, 6.5.1. 32

NGR, r. 87.

16

The decision to index the capital base has already been made for electricity in the

rules, and electricity service providers have not raised objections with the AER's

preferred approach.

To improve the smooth operation of the gas rules and to ensure that they reflect the

current regulatory approach, the rules should be amended to require gas pipeline

operators to index their capital bases. Because the gas rules are silent on indexing the

capital base, we have had gas businesses propose changing the capital base to be un-

indexed as a means to bring forward their cash flows.

Having the requirement that pipeline operators must index the capital base would

ensure a consistent treatment of the capital bases of all service providers operating

under a common building block framework.

Recommendation 3: To improve efficiency and consistency, pipeline operators should

be required to use the AER models (PTRM/RFM) as part of the access arrangement

review. We also recommend that the rules provide for explicit indexation of the capital

base.

4. Incentives to provide access to pipeline services

4.1 AEMC must ensure the AER is able to define reference

and rebateable services

Reference services, and the linked reference tariffs, form the foundation for

negotiations between pipeline operators and users. Appropriately defining reference

services is critical to the success of the negotiate-arbitrate model for gas regulation. It

is particularly important for transmission pipelines that offer a range of customised

pipeline services.

Rule 101 states that:

(1) A full access arrangement must specify as a reference service:

(a) at least one pipeline service that is likely to be sought by a significant part of the market; and

(b) any other pipeline service that is likely to be sought by a significant part of the market and which the AER considers should be specified as a reference service.

(2) In deciding whether to specify a pipeline service as a reference service, the AER must take into account the revenue and pricing principles.

The ‘test’ for whether a service is a regulated service is whether the service is likely to

be demanded by a significant part of the market. This is very different to the electricity

service classifications. The test for service classification in the NER is essentially

whether the service is contestable or not.

We consider that defining reference services according to market demand is still the

best approach. In sectors where services purchased by end users are typically

customised, it is appropriate for a regulatory framework to seek to set prices for

17

‘typical’ or ‘reference' services. As long as there is a reference service that is a close

substitute for the service the end user desires, each end customer can be effectively

protected against the exercise of market power.

Once a reference service is defined, we factor in demand, determine a revenue

forecast, allocate costs and make decisions on reference tariffs.

There are some services where it may be difficult to accurately forecast demand, and

therefore to forecast the future revenue requirement and tariffs. This could be because

either the price of the service, or the volume of sales is difficult to determine in

advance. It is important that a pipeline operator has incentives under the regulatory

regime to innovate and provide a variety of services. It is equally as important to

ensure the pipeline operator does not exercise unlimited market power with respect to

these types of services.

The rules allow the AER to define certain services, where demand is uncertain, as

rebateable services.33 These services must be in a substantially different market to the

reference service. If a service is defined as a rebateable service, the costs associated

with this service can, in whole or in part, be included in the calculation of the reference

tariff if an appropriate portion of revenue derived from the sales of this service is

returned to the reference service users through a rebate or refund.

The ACCC Inquiry stated that 'the reference service approach used in the NGR has

resulted in a number of non-contestable services being excluded from the AER’s ex

ante review, whereas non-contestable services are arguably a primary target for

regulation'.34

While we consider that the concept of 'reference services' is sound, there has been

debate in the past as to how to interpret rule 101 (that an access arrangement to

contain statement of reference services sought by a significant part of the market) and

its interaction with rule 93(4) (the definition of a rebateable service). For the AER this

has primarily been an issue in relation to transmission pipeline services (Box 2).

Box 2: Reference service and rebateable service rule change proposal

In 2011 we sought a rule change to the reference service and rebateable service definitions.

The request was triggered by concerns we had that APA was earning material revenue from the

sale of AMDQ Credit Certificates (AMDQ cc). Whilst AMDQ cc was sought by a significant part

of the market, we were reluctant to define it as a reference service due to difficulties in

estimating an efficient tariff.

We considered AMDQ cc was better defined as a rebateable service under rule 93(4) as there

was uncertainty regarding the revenue to be generated from the service. However, we

considered that the requirement for a rebateable service to be in a substantially different market

33

NGR, r.93(3). 34

ACCC, Inquiry into the East Coast Gas Market, April 2016, pp. 134-135.

18

from the market for any reference service may constrain our ability to effectively define pipeline

services.

At the time we took the view that AMDQ cc was in a similar market to the market for basic

transportation services.

We requested that the AEMC remove the requirement that the rebateable service be in a

substantially different market

The AEMC did not consider the potential benefits of making the proposed change to the

rebateable service definition outweigh the costs.35

Given the importance of appropriately defining reference services and rebateable

services, particularly in response to recent industry changes, we have undertaken

further consideration of the appropriate interpretation of the rules.

We consider that the appropriate approach to identifying 'reference services' is one

that is based on the economic and competition law concept of a market. In competition

law, markets are defined as groups of services which are close substitutes for each

other. Services which are not close substitutes for each other are in separate markets.

Given the variety of services pipelines offer, and the end user customisation, we

consider that ideally services that are close substitutes for each other could be

grouped together, and at least one reference service established for each group. In this

way each group of services represents a significant part of the overall (i.e. non-

economic) 'market'. It follows that services that are not close substitutes could be

represented through different reference services and reference tariffs. This is

consistent with the negotiate-arbitrate model and can assist us to ensure that regulated

reference services are available for as many non-substitutable services as required.

Following this reasoning, if a pipeline offered a service that was not a substitute for a

defined reference service, and there was uncertainty regarding the demand or revenue

to be generated from this service, it could be defined as a rebateable service.

We have followed this reasoning in our approach to defining the services covered in

our draft decision for the Roma to Brisbane 2017-2022 access arrangement review.36

In our draft decision we consider that the park and loan services and in-pipe trading

services offered by RBP should be defined as rebateable services. This was not

proposed by RBP and we have used our discretion under rule 93 (3) to make this draft

decision.

35

AEMC, Rule determination: National Gas Amendment (reference service and rebateable service definitions) Rule

2012, 1 November 2012, p. iii.

36

AER, Draft Decision Roma (Wallumbilla) to Brisbane Pipeline - Access arrangement 2017-22, 6 July 2017

<https://www.aer.gov.au/networks-pipelines/determinations-access-arrangements/roma-wallumbilla-to-brisbane-

pipeline-access-arrangement-2017-22/draft-decision>.

19

APA's response to our Draft Decision raises issues with our definition and treatment of

rebateable services.37 The draft decision and APA's revised proposal are currently out

for stakeholder comment. Submissions close on the 15 September 2017 and

comments are welcome.

Recommendation 4: The AEMC should ensure the rules place beyond doubt the

AER's ability to set multiple reference tariffs and to define and set rebateable services.

4.2 Introduce a mechanism to consult prior to access

arrangement reviews

The gas market is becoming more dynamic and we need to be able to adapt to

changes in the market. We need to be more engaged to ensure that we are approving

access arrangements that are reflective of the services being offered by the service

provider.

As discussed, the ACCC Inquiry found that pipelines subject to full regulation may

engage in monopoly pricing when negotiating the tariffs for non-reference services.38 A

possible solution is to define more services (as reference and rebateable services)

through the access arrangement process. In the past, most service providers only

provide for a single reference service in their access arrangements and consequently,

we have adopted the habit of only approving one reference service. We could establish

additional reference services under the current definitions of reference and rebateable

services but this is extremely difficult under the current timeframes.

Currently, it is not feasible for us to define additional reference services once an

access arrangement has been submitted as the timeframe for consideration of a

revised access arrangement is tight. In order to meet timelines we have felt

constrained to accept the design elements proposed by the service provider. This may

be despite our consideration of the issues raised by access seekers, for example, for

the consideration of alternative services or for more than one reference service. The

definition of the reference service(s) flows through into the demand, cost allocation and

ultimately tariff components of the proposal. The AER, the business and end-users

need time to appropriately consider all of the issues, form a decision on service

definitions and then flow this through into the other components of a decision.

Currently, a pipeline operator may request a ‘pre-submission conference’ before

submitting its full access arrangement proposal (rule 57(1)). This process can provide

substantial benefits to both parties and enables the pipeline operator to develop a

complete and well-framed proposal. However, rule 57 only provides for the service

provider to request a pre-submission conference. This means that we cannot initiate

any pre-proposal submission process.

37

See: https://www.aer.gov.au/system/files/APTPPL%20-%20Access%20arrangement%20submission%20-

%2014%20August%202017.pdf 38

ACCC, Inquiry into the east coast gas market, April 2016, p.135.

20

Given this, we recommend that the AEMC consider introducing a mechanism which

allows the regulator, the businesses and end users to be consulted, and determine the

services covered in an access arrangement before the access arrangement review

process commences. This mechanism could include other components that would

benefit from more stakeholder consultation prior to access arrangement proposals

being submitted, such as incentive schemes and the form of control.

The proposed process should be tailored to gas and should maintain the flexibility of

the gas rules. The process should not be compulsory. We recommend that the

mechanism could be triggered by the AER, the pipeline operator or shippers, when

there is a material change to the services offered (for example, either the business or

the AER wishes to propose changes to reference services or rebateable services),

incentive schemes or form of control. We envisage that the process could allow for one

round of stakeholder consultation before we are required to make a decision. This

decision should be made at least 6 months prior to the review commencing.

Recommendation 5: Introducing an upfront process to identify reference services,

rebateable services, application of incentives schemes and the form of control prior the

commencement of an access arrangement review.

4.3 Information requirements for light regulation should be

enhanced

Covered pipelines have been found to exercise market power. The light regulation

regime was introduced to provide a form of regulation that was suitable for pipelines

that were to some extent constrained in their ability to exercise market power, and

where the benefits of full regulation outweighed the costs. Light regulation is thought to

provide 'more timely and lower cost outcomes than full regulation'.39

Unlike full regulation, there is no ex ante approval of price and non-price terms of

reference services through access arrangements. If negotiations are successful, light

regulation gives rise to reduced front end costs and delay, but if unsuccessful and an

access dispute is triggered, the arbitration process would likely be longer and more

costly to undertake than in full regulation. These risks are considered by the NCC

when a light coverage determination is made.40 While we understand the differences

between full and light regulation, some of the features of the new GMRG framework for

non-scheme pipelines differ significantly from the existing light regulation approach.

The aim of this submission is not to comment on the future of light regulation but to

build a bridge between the GMRG framework and light regulation, until this issue can

be properly considered.

39

National Competition Council, Gas Guide: A guide to the functions and the powers of the National Competition

Council under the National Gas Law, October 2013, p. 65. 40

National Competition Council, Gas Guide: A guide to the functions and the powers of the National Competition

Council under the National Gas Law, October 2013.

21

Both the ACCC Inquiry and Dr Michael Vertigan’s Examination highlighted that

information asymmetry is at the heart of market power and consequently, monopoly

pricing. Information asymmetry gives rise to a power imbalance between shippers and

pipeline operators in negotiations. Shippers are unable to identify the extent of market

power because they do not have access to cost of service information. Shippers are

therefore unable to assess the reasonableness of the tariffs and terms offered. Access

to information levels the playing field and allows for more effective negotiation.

Building a bridge between the GMRG framework for non-scheme pipelines and

light regulation

The obvious gap between the light regulation regime and the GMRG framework is in

information disclosure. We consider that this gap is inappropriate.

The GMRG framework provides for pipeline operators to publish the information that

shippers need to make an informed decision about whether to seek access to a

pipeline service and to assess the reasonableness of an offer made by the pipeline

operator. The publication and exchange of this information is intended to facilitate

timely and effective commercial negotiations in relation to access to non-scheme

pipelines.41

A service provider for a non-scheme pipeline must prepare, maintain and publish:

service and access information42

standing terms43

financial information44

weighted average price information45

This information is to be published by service providers in accordance with the NGL,

Part 23 of the NGR and, where relevant, the financial reporting guideline that is

currently being developed. Information must be provided in accordance with the

access information standard and timetable set out in the rules. The timetable provides

for the publication of the first set of:

service and access information and standing terms by 1 February 2018; and

financial information and weighted average price information by October 2018 or

January 2019, depending on the service provider’s financial year.

This information is to be published on each service provider’s website.46

41

NGR, Part 23. 42

NGR, r. 553. 43

NGR, r. 554. 44

NGR, r. 555. 45

NGR, r. 556. 46

NGR, r 552.

22

The light regulation regime provides a limited amount of information for potential users.

A service provider must publish its tariffs and terms and conditions of access on its

website.47 The owner must also comply with the facilitation of, and request for, access

rules in the NGR. Under these rules, pipeline operators are required to provide certain

information to the AER, when requested by shippers who are seeking access to

pipeline services.48 Pipelines subject to light regulation must report to the regulator on

access negotiations and have minimal annual compliance obligations. Light regulation

places greater emphasis on commercial negotiations and information disclosure than

full regulation and users are accorded some degree of protection through the following

safeguards:

The dispute mechanism in the NGL and NGR,

Section 136 of the NGL, which prohibits a service provider of light regulatory

services from engaging in price discrimination, unless it is efficient to do so; and

Sections 133 and 137-148 of the NGL which are designed to present service

providers from engaging in conduct that may adversely affect third party access or

competition in other markets.49

There is still however a noticeable gap between non-scheme pipelines and pipelines

subject to light regulation in relation to information disclosure.

How to close the gap

We recommend that the AER be provided with greater information gathering powers

under Part 11 of the NGR in relation to scheme pipelines subject to light regulation. In

particular we consider the requirement in rules 107 and 108 should be reconsidered.

Currently, shippers need to request specific information from pipeline operators

through the AER.

The AER should have discretion to collect information that it considers necessary to

enable proper decisions around seeking access and for effective negotiation for

pipeline services. Further, more information should be available up front to access

seekers, either publicly or on request by an access seeker, without the need to involve

the AER as an intermediary. This information should build on the information required

under the GMRG framework. However, because we are dealing with covered

pipelines, we may require additional or different information. We would like to continue

to discuss with the AEMC and stakeholders the most appropriate type of information to

be collected and made available to access seekers. As recommended in the ACCC

Inquiry, with broader information gathering powers, the AER could consider increasing

annual reporting requirements for covered pipelines.

47

NGR, r.36. 48

NGR, rr. 107-108. 49

We release annual compliance reports and no breaches have been recorded. See our website:

https://www.aer.gov.au/networks-pipelines/compliance-reporting?f[0]=field_accc_aer_sector%3A5.

23

While there are costs associated with information disclosure, since the rules inception,

the AER has invested heavily in minimising the cost of information disclosure though

the development of a consistent, streamlined information gathering framework. This

provides certainty and consistency for all participants, and balances the cost of

information gathering with the benefits of having it available for the regulatory process.

Stakeholders have benefited from the significant investment the AER has made in

streaming information collection (a direct response to the 2004 report).50

Recommendation 6: Enhancing the AER's information disclosure powers over light

regulation pipelines. We consider the amount of public information should be expanded

and not just made available at the request of the access seeker via the regulator.

4.4 Arbitration mechanism should be clarified and more

transparent

The ACCC Inquiry found that market power is not being effectively constrained by the

threat of arbitration on scheme pipelines. It argued that shippers are discouraged from

triggering the access dispute provisions due to:

uncertainty around the potential costs and resources involved, and

uncertainty about the final outcome due to a lack of clarity around the

methodologies to be relied on by the AER and information asymmetry between

parties to the dispute.51

The negotiate/arbitrate model adopted in gas regulation, provides for arbitration by the

AER in the event of an access dispute. Chapter 6 of the NGL provides for the

arbitration of access disputes by the AER, with a few small additional provisions on

access disputes, outlined in Part 12 of the NGR. The AER has a non-binding guideline

to arbitration of access disputes for scheme pipelines that was last revised in 2008.52

We do not propose any changes to the rules in Part 12 of the NGR. We consider that

the best way forward is to simplify and amend our guideline, subject to the AEMC's

recommendations on information disclosure coming out of this review. This can be

facilitated by the rule changes that will be proposed by the AEMC as a result of this

review. We note that the absence of access disputes does not necessarily mean the

arbitration mechanism is not effective but our amended guideline would seek to

address the key concerns raised in the ACCC Inquiry; minimising uncertainty, costs

and time in the arbitration of access disputes. If the AEMC considered it appropriate,

some of these changes could later be reflected in the NGL and NGR. The aim is to

50

The Allen Consulting Group, Expert Panel on Energy Access Pricing: Report to the Ministerial Council on Energy,

April 2006, p. 130. 51

ACCC, Inquiry into the east coast gas market, April 2016, p. 101. 52

AER, Guideline for the resolution of distribution and transmission pipeline access disputes under the National Gas

Law and National Gas Rules, November 2008

<https://www.aer.gov.au/system/files/Access%20dispute%20guideline.pdf >.

24

make the arbitration mechanism more accessible so that it becomes a more effective

constraint on pipeline operators.

Specific issues to be addressed by amending the guideline

Lack of information disclosure leads to uncertainty about the outcome of arbitration

We are recommending that the AEMC initiate rule changes to provide the AER with

greater information gathering powers under Part 11 of the NGR in relation to scheme

pipelines.53 Information asymmetry is one of the key contributors to pipeline operators

exercising market power and therefore engaging in monopoly pricing. If there is greater

information disclosure, shippers will be better equipped to assess the reasonableness

of the price and non-price terms and conditions offered, resulting in effective

negotiation. Not only will this reduce the need for arbitration but it will provide parties

with greater certainty around the likely outcome of an access dispute, as they are able

to make their own judgments on the basis of the information provided before seeking

arbitration by the AER.

Uncertainty around timeframes for conducting arbitration

The NGL does not provide any timeframes for the conduct of arbitration. Subject to

amendments to the rules to allow for greater information disclosure, the AER would

amend its guideline to include timelines, providing certainty to participants. We would

seek to include stop the clock provisions and establish the maximum days it should

take to decide the different categories of access disputes.

Uncertainty around the methodologies the AER would use in arbitrating an access

dispute

The NGL does not explicitly refer to provisions in the NGR or how the AER would

assess the various components of an access dispute, such as price and revenue. The

AER would amend the guideline to ensure it is clear, for example, that the AER would

determine an access dispute in accordance with Part 9 of the NGR. We note that Part

23 of the NGR, which details the Information Disclosure and Arbitration Framework for

non-scheme pipelines, adopts an approach to asset valuation for pre 2008 pipelines

(and especially for pre 1997 pipelines) that differs from the approach in rule 77 of the

NGR. We would like to continue to discuss with the AEMC and stakeholders whether

an approach that is more closely tied to the depreciated cost of construction, and that

therefore provides greater certainty for stakeholders, should be adopted for arbitrations

on all pipelines.

Recommendation 7: Subject to acceptance of Recommendation 6, the AER can

improve the arbitration process through removing areas of uncertainty, introducing

clear timeframes and aiming to minimise costs for disputing parties in its arbitration

guideline. The AER would undertake a public process to revise its guidelines at the

53

Please see section 4.3 of this submission.

25

completion of the AEMC review. We are also cognisant of picking up lessons learnt

from the non-scheme arbitration process which commenced on 1 August 2017.

26

Attachment A: Gas pipelines subject to regulation by the AER

Type of

regulation

State/territory pipeline Distribution or

transmission

Full Northern Territory Amadeus gas pipeline Transmission

Full Queensland Roma to Brisbane gas pipeline Transmission

Full Victoria APA Victorian transmission

system

Transmission

Full New South Wales Central Ranges Pipeline Distribution and

Transmission

Full ACT ActewAGL Distribution

Full South Australia Australian Gas Networks Distribution

Full Victoria Australian Gas Networks

(Albury,Vic)

Distribution

Full Victoria AusNet Services Distribution

Full Victoria Multinet Gas Distribution

Full New South Wales Jemena Gas Networks Distribution

Light NSW Central West Pipeline

(Marsden to Dubbo)

Transmission

Light Queensland Carpentaria Gas pipeline Transmission

Light NSW Moomba to Sydney

(unregulated Moomba to

Marsden)

Transmission

Light Queensland APT Allgas Energy Networks Distribution

Light Queensland AGN - gas distribution network Distribution